EXHIBIT 3
                                                                       ---------





         MANAGEMENT'S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003


<PAGE>

MANAGEMENT DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") should be read in conjunction with
the audited consolidated financial statements for the year-ended December 31,
2003 and the audited consolidated financial statements and MD&A for the
year-ended December 31, 2002.

Management uses cash flow (before changes in non-cash working capital) to
analyze operating performance and leverage. Cash flow as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other entities. Cash
flow as presented is not intended to represent operating cash flow or operating
profits for the period nor should it be viewed as an alternative to cash flow
from operating activities, net earnings or other measures of financial
performance calculated in accordance with Canadian GAAP. All references to cash
flow throughout this MD&A are based on cash flow before changes in non-cash
working capital.

Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks"), finding, development and
acquisition costs ("FD&A"), recycle ratio and total capitalization to analyze
financial and operating performance. These KPI's and benchmarks as presented do
not have any standardized meaning prescribed by Canadian GAAP and therefore may
not be comparable with the calculation of similar measures for other entities.

This discussion and analysis contains forward-looking statements relating to
future events or future performance. In some cases, forward-looking statements
can be identified by terminology such as "may", "will", "should", "expects",
"projects", "plans", "anticipates" and similar expressions. These statements
represent management's expectations or beliefs concerning, among other things,
future operating results and various components thereof or the economic
performance of ARC. The projections, estimates and beliefs contained in such
forward-looking statements necessarily involve known and unknown risks and
uncertainties, including the business risks discussed in the MD&A as at and for
the years ended December 31, 2003 and 2002, which may cause actual performance
and financial results in future periods to differ materially from any
projections of future performance or results expressed or implied by such
forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause results to differ materially from those predicted.

<TABLE>
<CAPTION>
HIGHLIGHTS
CDN$ Millions, except per unit and volume data                     2003         2002 (3)
---------------------------------------------------------------------------------------
<S>                                                          <C>             <C>
Cash flow from operations (1)                                $      396      $     224
Cash flow from operations per unit                           $     2.56      $    1.87
Net Income                                                   $      290      $      71
Net Income prior to non recurring items (2)                  $      290      $      97
Distributions per unit                                       $     1.80      $    1.56
Daily production (boe/d) (4)                                     54,335         42,425
=======================================================================================
</TABLE>

(1)  Before changes in non-cash working capital.

(2)  Prior to a one time change related to the internalization of the management
     contract in 2002.

(3)  2002 net income has been restated for a retroactive change in accounting
     policy relating to Asset Retirement Obligations.

(4)  Production amounts are based on company interest before royalties.

o    On April 16, 2003, ARC Energy Trust ("ARC" or "the Trust") completed the
     acquisition of Star Oil & Gas Ltd. ("Star") for total consideration of
     $721.6 million after final closing adjustments. Subsequent to closing, ARC
     completed the disposition of certain Star properties for total proceeds of
     $78.2 million.

o    Strong commodity prices, excellent drilling results and increased
     production volumes as a result of the Star acquisition resulted in record
     cash flow of $396.2 million ($2.56 per unit) in 2003 compared to $224
     million ($1.87 per unit) for 2002. The year-over-year increase in cash flow
     of $172 million was due primarily to the Star acquisition and higher
     commodity prices, especially for natural gas. The continued strengthening
     of the Canadian dollar relative to the U.S. dollar had a negative impact in
     the third and fourth quarters. The rise of the Canadian/U.S. exchange rate
     by 22 per cent during 2003 materially decreased the Canadian dollar
     denominated commodity prices realized by the Trust and all other Canadian
     energy companies.

o    The Trust declared distributions of $279.3 million in 2003 ($1.80 per unit)
     and $183.6 million in 2002 ($1.56 per unit), representing 71 per cent and
     82 per cent of 2003 and 2002 cash flow. The payout ratio would have been 72
     per cent and 83 per cent of cash flow in 2003 and 2002, respectively,
     taking into account that holders of the

<PAGE>

MD&A
Page 2
--------------------------------------------------------------------------------


     exchangeable shares forego cash distributions in favour of an increase in
     exchange ratios thereby effectively re-investing approximately $5.5 million
     and $3.2 million in 2003 and 2002, respectively.

o    During the third quarter, ARC completed the disposition of certain of its
     minor, non-core properties for total consideration of $77 million before
     final closing adjustments. The disposition of the minor, non-core
     properties will allow the Trust to focus on development opportunities in
     its core areas.

o    The Trust successfully completed three major equity offerings: February
     2003 and November 2003 equity offerings netted $136 million and $184
     million respectively. In addition, in conjunction with the Star
     acquisition, $320 million of debentures were issued and subsequently
     converted into 27 million Trust units between May and August 2003.

The Trust has obtained Board of Director approval to proceed with a $175 million
capital expenditure program in 2004.

ACQUISITION OF STAR OIL & GAS LTD.

On April 16, 2003, ARC completed the acquisition of Star for total consideration
of $721.6 million after final closing adjustments. The acquisition was funded
through a combination of bank debt and the issuance to the vendor of $320
million in special convertible subordinated debentures. In related transactions
that closed on May 2, 2003, ARC sold certain producing properties and
undeveloped acreage comprising part of the acquired assets to third parties for
$78.2 million.

The Trust recorded goodwill of $157.6 million on the acquisition of Star. The
goodwill arose as a result of the Trust purchasing tax pool deficient oil and
gas reserves. The goodwill value was determined based on the excess of total
consideration paid plus the future income tax liability recorded upon
acquisition less the deemed fair value of the Star assets. The fair value, for
accounting purposes, of the Star assets of $794 million was determined based on
a 10 per cent discounted value of established reserves as per an independent
reserve evaluation, which compares favourably to the $721.6 million
consideration paid after closing adjustments. The difference represents ARC's
view of the fair value of the tax pool deficiency.

The operations of Star have been included in the consolidated financial
statements of the Trust effective April 16, 2003, the closing date of the
acquisition.

All of the convertible debentures that were issued as partial consideration for
the Star acquisition were converted into trust units by the end of the third
quarter of 2003.

PRODUCTION

Production volumes during 2003 averaged 54,335 boe/d compared to 42,425 boe/d in
2002. This represents a 28 per cent increase. The Trust's 2003 production
portfolio was weighted 42 per cent oil, 50 per cent natural gas and eight per
cent natural gas liquids ("NGL's") on a per boe basis. The increase in
production was attributed to the acquisition of Star that closed on April 16,
2003 and the results of the 2003 capital expenditure program. The acquisition of
Star (net of related property dispositions) resulted in an increase in
production of approximately 18,000 boe/d from April 16, 2003 to year-end.
Production was impacted by the sale of minor properties with production of
approximately 3,700 boe/d, most of which closed on August 14, 2003.

In 2003, 11 properties located within the Trust's five core areas accounted for
42 per cent of the Trust's production with no one property accounting for more
than eight per cent of total production. This diversification of production
minimizes the risk that operating problems at a specific property will
materially impact the Corporation.

PRODUCTION                                  2003            2002       % Change
-------------------------------------------------------------------------------
Crude oil (bbl/day)                       22,886          20,655           10.8
Gas (mcf/day)                            164,180         109,745           49.6
NGL (bbl/day)                              4,086           3,479           17.4
-------------------------------------------------------------------------------
Total Production (boe/d)                  54,335          42,425           28.1
===============================================================================

PRODUCTION SPLIT                            2003            2002
-------------------------------------------------------------------------------
Crude oil and natural gas liquids            50%             57%
Natural Gas                                  50%             43%
-------------------------------------------------------------------------------
Total (boe/d)                               100%            100%
===============================================================================

<PAGE>

MD&A
Page 3
--------------------------------------------------------------------------------


ARC expects 2004 production to average approximately 55,000 boe/d after
incorporating production declines on existing properties and the positive impact
of ongoing development activities on the assets.

MARKETING AND PRICES

PRICES AND MARKETING                          2003             2002     % Change
--------------------------------------------------------------------------------
BENCHMARK PRICES
AECO gas ($/mcf)                         $    6.67        $    4.08          63
WTI oil (U.S. $/bbl)                     $   31.06        $   26.10          19
CDN/USD Foreign exchange rate            $    0.71        $    0.64          11
WTI oil (CDN equivalent/$/bbl)           $   43.57        $   41.06           6

AVERAGE ARC PRICES*
Natural gas ($/mcf)                      $    6.21        $    4.41          41
Oil ($/bbl)                              $   34.48        $   31.63           9
Natural gas liquids ($/bbl)              $   32.19        $   24.01          34
--------------------------------------------------------------------------------
Total oil equivalent ($/boe)             $   36.87        $   28.73          28
===============================================================================
* Includes commodity and foreign currency hedging gains and losses. See hedging
  section for details.

West Texas Intermediate at Cushing, Okalahoma (WTI) is the benchmark for North
American crude oil prices. The WTI oil price averaged US$31.06 per barrel in
2003, up from US$26.10 per barrel in 2002. Canadian crude oil prices are based
upon refiners' postings, primarily at Edmonton, Alberta, and represent the WTI
price, adjusted for transportation and quality differentials and the
Canadian/U.S. exchange rate. ARC's average field price reflects the refiners'
posted price at Edmonton, Alberta less deductions for transportation from the
field and adjustments for ARC's product quality relative to the posted price.
ARC's average field price in 2003 was $38.04 per barrel ($35.27 per barrel in
2002) compared to $43.11 per barrel ($39.71 per barrel in 2002) for the average
of the light sweet postings at Edmonton. The small discount to the average
Edmonton posted price reflects the high quality of ARC's crude oil mix, which
comprises 44 per cent light sweet (greater than 35(0) API) crude, 51 per cent
medium gravity and five per cent heavy gravity oil (less than 23(0) API). ARC's
average oil price, net of all hedging transactions, in 2003 was $34.48 per
barrel, as compared to $31.63 per barrel in 2002.

U.S. natural gas prices are typically referenced off NYMEX at the Henry Hub,
Louisiana, while western Canada natural gas prices are referenced to the AECO
Hub in Alberta.

AECO Hub prices were $6.67 per mcf and $4.08 per mcf for 2003 and 2002,
respectively, an increase of 63 per cent. ARC's average well head gas price,
prior to hedging transactions, increased by 63 per cent to $6.30 per mcf in 2003
from $3.86 per mcf in 2002. ARC's average gas price after hedging transactions
was $6.21 per mcf and $4.41 per mcf in 2003 and 2002, respectively.

The 22 per cent increase in the Canadian dollar relative to the U.S. dollar had
a negative impact on the Canadian denominated prices received by the Trust in
2003.

The Trust has entered into foreign exchange hedging contracts to somewhat
mitigate the impact that fluctuations in the CAD/USD exchange rate have on cash
flow. In addition, certain of the Trust's payments are denominated in U.S.
dollars which partially offsets the negative impact of CAD/USD exchange rate
fluctuations.

In July 2003, the Trust announced the formation of Energy Trust Marketing Ltd.
("ETML"), a natural gas marketing company, which is jointly owned by ARC, four
other Alberta based energy trusts, and the management of ETML. ETML enhances
ARC's options for marketing its natural gas production.

HEDGING AND RISK MANAGEMENT

The Trust uses a variety of derivative instruments to manage its exposure to
fluctuations in commodity prices and foreign currency rates. The types of
contracts consist primarily of fixed price swaps, collared contracts, max
payouts and three-way collars. As at December 31, 2003, the Trust would have had
to pay $18.6 million to terminate these contracts. See Note 9 to the financial
statements for further details of the derivative instruments.

The Trust's hedging activities are conducted by an internal Risk Management
Committee, which has the following objectives as its mandate:

<PAGE>

Page 4
--------------------------------------------------------------------------------


     o   protect unitholder return on investment;

     o   stabilize monthly distributions;

     o   employ a portfolio approach to hedging by entering into a number of
         small positions that build upon each other;

     o   participate in commodity price upturns to the greatest extent possible,
         while limiting exposure to price downturns; and,

     o   ensure profitability of specific oil and gas properties that are more
         sensitive to changes in market conditions.

The Trust's 2003 prices included a hedging loss of $0.09 per mcf for natural
gas, a loss of $3.56 per barrel for oil and a gain of $0.98 per boe for foreign
currency hedge contracts. The 2002 prices included a hedging gain of $0.55 per
mcf for natural gas, a loss of $3.64 per barrel for oil and a loss of $0.12 per
boe for foreign currency hedge contracts.

For 2004, ARC has currently hedged approximately 44 per cent of oil production
volumes at an average WTI price of approximately US$28.00 per barrel and 32 per
cent of natural gas production volumes utilizing a variety of contracts at an
average AECO price of approximately $5.95 per mcf. The Trust's Risk Management
Committee is authorized by the Board of Directors of ARC Resources Ltd. ("ARC
Resources" or "ARL") to hedge up to 50 per cent of the Trust's production on a
boe basis for a period of up to 12 months, and up to 25 per cent of the Trust's
production for the next consecutive 12 month period.

2003 cash flow from operations includes $11.9 million that was received upon
termination of foreign exchange hedge contracts. This one-time cash settlement
was included in 2003 cash flow from operations and is being amortized to
earnings over the term of the original contracts to March 2004. The Trust has
entered into foreign exchange hedge contracts to manage its exposure to
fluctuations in CDN/USD exchange rate (see Note 9 to the audited consolidated
financial statements ("Financial Statements") for details on ARC's commodity and
foreign exchange hedging contracts).

Revenue ($Millions, includes hedging)                2003       2002   % Change
-------------------------------------------------------------------------------
Oil revenue                                         288.0      238.5         21
Natural gas revenue                                 372.2      176.6        111
Condensate and NGL revenue                           48.0       30.5         57
Other revenue                                        23.0      (0.8)          -
Total revenue                                       731.2      444.8         64
===============================================================================

Revenue, prior to commodity and foreign currency hedging transactions, increased
to $747.2 million in 2003 compared to $453.6 million in 2002. The increase was
primarily due to the acquisition of Star and higher commodity prices. Hedging
losses on commodities and foreign currency of $16 million in 2003 and $8.8
million in 2002 resulted in production revenue net of hedging losses of $731.2
million in 2003 and $444.8 million in 2002.

OPERATING NETBACKS

A 2003 operating netback of $22.16 per boe compared to $16.78 per boe in 2002
reflected the 63 per cent increase in natural gas prices and 19 per cent
increase in crude oil prices offset by the 11 per cent decline in the average
CDN/USD exchange rate.

Operating costs include all costs associated with the production of oil and
natural gas from the time the well commences commercial production to the point
at which the product enters a pipeline for transport or is trucked to a
commercial market. Gathering and processing costs are also included in operating
costs. Costs to transport the product from the wellsite to the commercial market
are not reflected as an operating cost but are netted against the revenue
received for the product. Revenue received from the processing of third-party
production at ARC's facilities is netted against operating costs.

Operating costs, net of processing income, increased to $140.7 million ($7.10
per boe) for 2003 from $99.9 million ($6.45 per boe) for the same period in
2002. The increase in the dollar amount of operating costs from 2002 to 2003 was
primarily due to the acquisition of Star. The increase in 2003 electricity rates
in the province of Alberta had a direct impact on operating costs as electricity
is one of the largest components of the Trust's operating cost structure. ARC
has hedged approximately 20 per cent of its total electricity usage at a price
of $63 per megawatt hour through to December 2010. Increases in well service and
work-over costs impacted operating costs in total and on a per boe basis in
2003. ARC continues to closely manage and monitor costs on operated and
non-operated properties. In benchmarking operating costs to our peer group, it
is evident that the increase in operating costs per boe is in line with overall
industry trends and is consistent with similar cost increases facing our peers.

<PAGE>

MD&A
Page 5
--------------------------------------------------------------------------------


The Trust pays crown, freehold and overriding royalties that are dependent upon
production volumes, commodity prices, location and age of producing wells and
type of production. Oil crown royalty volume, which is taken in kind in Alberta,
is assigned a dollar value based on the sales price that otherwise would have
been received for the oil crown royalty volume. Crown royalties for natural gas,
NGL's, and oil produced outside of Alberta are assigned a dollar value based on
a posted reference price. Gas crown royalties are reduced by Gas Cost Allowance
("GCA") deductions. The GCA deductions are based on processing fees and
allowable capital costs incurred at a property and are in accordance with
royalty agreements for the property. Royalty income received is included in
revenue. The effective royalty rates applicable to the Trust's 2003 oil, natural
gas and NGL production were 19 per cent, 21 per cent, and 26 per cent,
respectively.

Total royalties increased to $7.61 per boe in 2003 as compared to $5.50 per boe
in 2002. Royalties as a percentage of pre-hedged revenue increased to 20.2 per
cent as compared to 18.8 per cent for the same period in 2002. The higher
royalty rate in 2003 is attributed to the higher commodity price environment and
the increased gas weighting of the Trust's production, as the Trust's effective
royalty rate on natural gas is higher than oil. The increase in 2003 royalties
per boe is attributed to the higher commodity price environment and the drilling
of higher production rate wells.

The components of operating netbacks are shown below:

<TABLE>
<CAPTION>
                                                                              2003
                                             ----------------------------------------------------------------------
NETBACK                                      Oil ($/bbl)         Gas ($mcf)        NGL ($/bbl)       Total ($/boe)
-------------------------------------------------------------------------------------------------------------------
<S>                                          <C>                 <C>               <C>               <C>
Market price                                      38.04               6.30              32.19               37.67
Cash hedging gain (loss) (2)                      (3.56)             (0.16)                --               (1.09)
Non-cash hedging gain (loss) (2)                     --               0.07                 --                0.29
-------------------------------------------------------------------------------------------------------------------
Selling price                                     34.48               6.21              32.19               36.87
Royalties                                         (7.09)             (1.32)             (8.55)              (7.61)
Operating costs (1)                               (8.38)             (1.02)             (6.51)              (7.10)
-------------------------------------------------------------------------------------------------------------------
Netback                                           19.01               3.87              17.13               22.16
===================================================================================================================

<CAPTION>
                                                                              2002
                                            -----------------------------------------------------------------------
NETBACK                                     Oil ($/bbl)         Gas ($mcf)         NGL ($/bbl)       Total ($/boe)
-------------------------------------------------------------------------------------------------------------------
<S>                                         <C>                 <C>                <C>               <C>
Market price                                      35.27               3.86              25.24               29.31
Cash hedging gain (loss) (2)                      (2.01)              0.18              (1.23)              (0.83)
Non-cash hedging gain (loss) (2)                  (1.63)              0.37                 --                0.25
-------------------------------------------------------------------------------------------------------------------
Selling price                                     31.63               4.41              24.01               28.73
Royalties                                         (6.47)             (0.71)             (6.31)              (5.50)
Operating costs (1)                               (7.37)             (0.92)             (5.79)              (6.45)
-------------------------------------------------------------------------------------------------------------------
Netback                                           17.79               2.78              11.91               16.78
===================================================================================================================
</TABLE>

(1)  Operating expenses are composed of direct costs incurred to operate both
     oil and gas wells. A number of assumptions have been made in allocating
     these costs between oil, natural gas and natural gas liquids production.

(2)  Gains and losses on foreign currency hedge contracts are not allocated to
     the individual commodity have netbacks. Foreign currency hedging gains of
     $0.98/boe have been included in the total 2003 netback and losses of
     $0.12/boe have been included in the total 2002 netback.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses ("G&A") include costs incurred by the Trust
which are not directly associated with the production of oil and natural gas.
The most significant components of G&A expenses are office employee compensation
costs and office rent. Employee compensation costs for field employees are
charged to operating expenses. Overhead recoveries resulting from the allocation
of administrative costs to partners are recorded as a reduction of G&A expenses.

G&A expenses, net of overhead recoveries on operated properties, increased in
2003 to $22.6 million ($1.14/boe) from $15.4 million ($0.99/boe) in 2002. The
increase in total G&A costs was due primarily to costs associated with an
increase in staffing levels as a result of the Star acquisition and a $3.5
million ($0.18/boe) non-cash G&A item relating to the value of benefits given to
officers, directors, employees and contract employees under the Trust's Trust
Unit Incentive Plan (see Notes 3 and 15 to the Financial Statements for
additional information). The Trust's G&A costs per boe excluding non-cash G&A
have remained relatively consistent year-over-year and are continuously
monitored internally by management and are benchmarked against other comparable
sized Trusts. The Trust expects 2004 G&A costs excluding non-cash G&A to
increase slightly in 2004 as a result of a full year of increased G&A costs
following the Star acquisition and the increased capital expenditure program of
$175 million in 2004.

<PAGE>

MD&A
Page 6
--------------------------------------------------------------------------------


<TABLE>
<CAPTION>
                                                                2003                            2002
----------------------------------------------------------------------------------------------------------------
General and Administrative Expense                  $ MILLIONS       $ PER BOE      $ millions         $ per Boe
----------------------------------------------------------------------------------------------------------------
<S>                                                 <C>              <C>             <C>               <C>
Cash G&A                                                  19.1            0.96             15.4             0.99
Non-cash G&A                                               3.5            0.18               --               --
----------------------------------------------------------------------------------------------------------------
Total G&A                                                 22.6            1.14             15.4             0.99
================================================================================================================
</TABLE>

Prior to the internalization of the management contract in the third quarter of
2002, the Manager received three per cent of net operating revenue. In 2002,
management fees through to the August 29 internalization date, amounted to $5.2
million ($0.33/boe). There are no management fees payable subsequent to the
internalization that occurred on August 29, 2002.

INTEREST EXPENSE

Interest expense increased to $18.5 million in 2003 from $12.6 million in 2002
as a result of a higher monthly average debt balance following the Star
acquisition and in addition, a higher effective interest rate during the year.
The Trust's effective interest rate increased to 5.3 per cent in 2003 compared
to 4.4 per cent in 2002. This was due primarily to weighting of fixed rate debt
to short-term debt as a result of proceeds received from the two equity
offerings completed in 2003. Long-term debt was reduced in February and November
with net proceeds from equity offerings of $136 million and $184 million,
respectively. Interest expense was minimized over the course of the year by
financing debt through the issuance of lower cost bankers' acceptances as
opposed to borrowing at the prevailing bank prime interest rates.

On April 16, 2003, the Trust issued $320 million of convertible debentures to
the shareholders of Star as partial consideration for the acquisition.
Throughout the second and third quarters, the debentures were converted into 27
million trust units. Due to the equity classification of the debentures,
interest on the debentures has not been included in interest expense but has
been recorded as a reduction of accumulated earnings. In 2003, $4.1 million of
interest on the convertible debentures was paid to debenture holders.

FOREIGN CURRENCY GAINS AND LOSSES

ARC has US$93.4 million in U.S. denominated long-term debt that is subject to
changes in the Canadian/U.S. dollar exchange rate. The unrealized gains and
losses associated with the fluctuations in the exchange rate are recorded in
income based upon the change in foreign exchange rates between reporting periods
(see Note 7 to the Financial Statements for additional information).

Due to the strengthening of the Canadian dollar in relation to the U.S. dollar
during 2003, ARC recorded an $18.6 million foreign exchange gain compared to a
gain of $0.6 million in 2002. Of this amount, $18.7 million is an unrealized
gain relating to the U.S. debt and has no impact on cash flow.

The $11.9 million cash settlement received upon termination of foreign exchange
hedge contracts was included in 2003 cash flow from operations. The settlement
amount was recorded on the balance sheet and is being amortized into income over
the remaining term of the contracts that were to expire at various dates through
March 2004. As at December 31, 2003, $10.5 million of foreign exchange hedge
termination amount has been included in 2003 revenue and the remaining $1.4
million will be amortized in the first quarter of 2004. An additional non-cash
amortization gain of $1.5 million relating to foreign exchange hedge contracts
was included in 2003 revenue.

TAXES

Capital taxes paid or payable by ARC, based on debt and equity levels at the end
of the year, amounted to $1.8 million in 2003 versus $1.4 million in 2002. The
increase in 2003 capital taxes was attributed to the higher taxable capital base
as a result of the Star acquisition.

In 2003, a future income tax recovery of $93.5 million was included in income
compared to a $27.9 million recovery in 2002. The significant 2003 future income
tax recovery is due to reductions in federal and provincial income tax rates.
The reductions in future tax rates were substantively enacted late in the second
quarter of 2003 and were subsequently legislated on November 7, 2003 when Royal
Assent was received. The future rate reductions will be phased in over five
years commencing in 2003. The rate changes incorporate a reduction in the
applicable tax rate on resource income from 28 per cent to 21 per cent, provide
for the deduction of crown royalties and eliminate over time the deduction for
resource allowance. ARC's expected future income tax rate incorporating these
changes is 35 per cent compared to 42 per cent as at December 31, 2002. Of the
$93.5 million 2003 future income tax recovery, $66.1 million was attributed to
the reduction in the future tax rate.

A future tax liability of $242 million was recorded upon acquisition of Star as
a result of the fair market value for accounting purposes of the assets acquired
being in excess of the associated tax basis. The future tax liability was

<PAGE>

MD&A
Page 7
--------------------------------------------------------------------------------


based on the tax rate at the time of acquisition of approximately 42 per cent.
The subsequent reduction in the future income tax rates resulted in a $39.2
million recovery of the future income tax liability recorded on the Star
acquisition.

In the Trust's structure, payments are made between ARC Resources and the Trust,
transferring both income and future tax liability to the unitholders. At the
current time, ARC does not anticipate any cash taxes will be paid by ARC
Resources.

DEPLETION, DEPRECIATION AND ASSET RETIREMENT OBLIGATION

The 2003 depletion, depreciation and accretion ("DD&A") rate increased to $11.02
per boe from $10.13 per boe in 2002 primarily due to the Star acquisition. The
DD&A rate includes depletion of $4.2 million ($3.2 million in 2002) on the
capitalized cost associated with the asset retirement obligation as well as
accretion expense on the asset retirement obligation of $3 million in 2003 ($2.6
million in 2002). The retroactive application of the new accounting policy for
asset retirement obligations required restatement of prior periods, which
resulted in a decrease in the 2002 DD&A rate to $10.13 per boe from the
previously reported DD&A rate of $10.45 per boe.

The increase in the 2003 DD&A rate is primarily due to the acquisition of Star,
which increased property, plant and equipment ("PP&E") by $794 million. This
amount was included in the depletable base effective April 16, 2003. Besides the
Star acquisition, assets to be depleted were increased by future development
costs of $315.8 million and reduced by $19.3 million for the estimated future
net realizable value of production equipment, $50 million for the value of
unproven properties, and $161.6 million for the proceeds of net property
dispositions completed in 2003.

The goodwill value of $157.6 million was determined based on the excess of total
consideration paid plus the future income tax liability less the fair value of
the Star assets. The future income tax liability is based on the difference
between the value allocated to Star's net assets and their respective tax basis.
The fair value, for accounting purposes, of the Star assets of $794 million was
determined based on a 10 per cent discounted value of established reserves as
per an independent reserve evaluation, which compares favourably to the $721.6
million consideration paid after closing adjustments. The difference represents
ARC's view of the fair value of the tax pool deficiency, which is different from
the amount of future taxes that must be provided on the acquisition under
Canadian GAAP.

Accounting standards require that the goodwill balance be assessed for
impairment at least annually and if such an impairment exists that it be charged
to income in the period in which the impairment occurs. The Trust has determined
that there is no goodwill impairment as of December 31, 2003.

CAPITAL EXPENDITURES AND NET ACQUISITIONS

Total capital expenditures, including net property and corporate acquisitions,
aggregated to $715.7 million in 2003 ($207.4 million in 2002). Of the total,
$155.8 million was incurred on drilling and completions, geological, geophysical
and facilities expenditures, as ARC continues to develop its asset base, with
the remaining $560 million attributable to net property and corporate
acquisitions. Total reserve acquisition and development costs for 2003,
including the change in future development costs per the independent engineering
reports, were $10.54 per boe compared to $10.79 per boe in 2002.

2003 capital expenditures and net property acquisitions include the corporate
acquisition of Star for total consideration of $721.6 million after closing
adjustments. PP&E increased by $794 million as a result of the acquisition. PP&E
includes an incremental amount to reflect the acquired assets at fair value for
accounting purposes after consideration of the future income tax liability
recorded on the acquisition.

A breakdown of capital expenditures by category is shown below:

Capital expenditures ($thousands)                               2003       2002
--------------------------------------------------------------------------------
Geological and geophysical                                     5,671      1,966
Drilling and completions                                     110,277     70,074
Plant and facilities                                          36,457     14,357
Other capital                                                  3,359      1,881
--------------------------------------------------------------------------------
Total capital expenditures                                   155,764     88,278
Producing property net acquisitions (dispositions)(1)       (161,609)   119,113
Corporate acquisition (2)                                    721,590         --
--------------------------------------------------------------------------------
Total capital expenditures and net acquisitions              715,745    207,391
================================================================================

Total capital expenditures financed with cash flow           106,625     35,612
Total capital expenditures financed with debt & equity       609,120    171,779
================================================================================
(1)  Value is net of post-closing adjustments.

<PAGE>

MD&A
Page 8
--------------------------------------------------------------------------------


(2)  Corporate acquisition of $721.6 million represents total consideration
     after closing adjustments. PP&E increased by an additional $72.5 million as
     a result of the future income tax liability arising upon acquisition.

The Board of Directors of ARC Resources has approved a capital budget of $175
million for 2004. This budget ranks individual projects to allow for revisions
during the year in the event the Trust acquires additional properties with
associated development opportunities, or there is a change in the business
environment which may result in the acceleration or delay of certain
expenditures. The Trust intends to withhold up to 20 per cent of 2004 cash flow
to fund the 2004 capital expenditure program with the remainder to be funded
with debt. The net proceeds of the November 2003 equity offering of $184 million
were applied to reduce the long-term debt balance in anticipation of the 2004
capital expenditure program.

ABANDONMENTS

ARC Resources takes a proactive approach to environmental issues and
abandonments and reclamation of associated well and facility sites as required.
ARC Resources annually carries out a program to abandon and reclaim wells and
facilities, which have reached the end of their economic lives. ARC has
established a reclamation fund into which $6.2 million cash and interest income
was contributed during the year ($4.8 million in 2002). During 2003, $2.2
million of actual abandonment costs were incurred of which $1.9 million was
funded out of the reclamation fund balance. At December 31, 2003, there was a
fund balance of $17.2 million. This fund, invested in money market instruments,
is established to provide for future abandonment liabilities. Future
contributions are currently set at approximately $6 million per year in order to
provide for the total estimated future abandonment and site reclamation costs.
ARC has been active in improving the quality of its oil and gas reserve base by
purchasing properties and then selling smaller lower quality properties that
tend to have a shorter reserve life and therefore a shorter time period to the
eventual abandonment of the property. This practice will continue in the future
in order to mitigate actual future abandonment costs.

<TABLE>
<CAPTION>
CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY

A breakdown of the Trust's capital structure is as follows:

($thousands except per unit and per cent amounts)                         2003         2002
-------------------------------------------------------------------------------------------
<S>                                                                  <C>          <C>
Long-term debt                                                         223,355      337,728
Short-term debt                                                          9,047           --
Working capital deficit excluding short-term debt                       29,669       10,067
-------------------------------------------------------------------------------------------
Net debt obligations                                                   262,071      347,795
Units outstanding and issuable for exchangeable shares (thousands)     182,777      126,444
Market price at end of period                                           $14.74       $11.90
Market value of Trust units and exchangeable shares                  2,694,133    1,504,684
Total ARC capitalization (1)                                         2,956,204    1,852,479
===========================================================================================
Net debt as a percentage of total capitalization                           8.9%        18.8%
-------------------------------------------------------------------------------------------
Net debt obligations                                                   262,071      347,795
-------------------------------------------------------------------------------------------
Cash flow                                                              396,180      223,969
-------------------------------------------------------------------------------------------
Net debt to cash flow                                                      0.7          1.6
===========================================================================================
</TABLE>

(1)  Total capitalization as presented does not have any standardized meaning
     prescribed by Canadian GAAP and therefore it may not be comparable with the
     calculation of similar measures for other entities. Total capitalization is
     not intended to represent the total funds from equity and debt received by
     the Trust.

As at December 31, 2003, the Trust had a working capital deficiency excluding
short-term debt, of $29.7 million compared to $10.1 million as at December 31,
2002. The 2003 year-end working capital deficit is a result of normal operating
conditions in periods when the Trust incurs significant capital expenditures.
ARC participated in significant capital projects near the end of the year
resulting in accrued capital expenditures of $33 million at December 31, 2003
compared to $21.6 million at December 31, 2002.

Total debt outstanding, inclusive of short and long-term debt, at December 31,
2003 was $232.4 million, which includes Canadian dollar bank debt of $111.3
million, U.S. dollar bank debt of US$28.4 million (CDN$37 million) and US$65
million (CDN$84 million) of Senior Secured Notes. ARC Resources' oil and gas
properties secure the debt. The Trust expects to be able to keep its credit
lines at $620 million, pending the annual credit review with its lenders.

The Trust's lending facilities consist of bilateral agreements with five
Canadian chartered banks and one U.S. insurance company. As the Trust's revenue
stream is tied to the value of oil and natural gas in the United States, the
Trust has chosen to borrow approximately one-half of its debt in U.S. dollars.
The Trust now has one-third of its debt

<PAGE>

MD&A
Page 9
--------------------------------------------------------------------------------


locked in at fixed interest rates averaging 6.6 per cent and the remaining
two-thirds floating based upon Canadian and U.S. banker's acceptance rates plus
a bank stamping fee.

End-of-year 2003 net debt to total capitalization was 8.9 per cent (18.8 per
cent in 2002) and net debt to annualized cash flow was approximately 0.7 times
(1.6 times in 2002) based upon cash flow from operations of $396.2 million and
net debt of $262.1 million. With the low level of debt, the 2004 repayment of
CDN$9 million (US$7 million) on the Secured Notes will be financed by a draw on
the ARC Resources credit facilities.

The Trust's current plans are to finance the approved 2004 capital budget of
$175 million with a combination of cash flow and debt. Debt balances were
reduced by the proceeds of the November 2003 equity offering (see Unitholders'
Equity).

Currently, several Canadian conventional oil and gas trusts have obtained stock
exchange listings in the United States in order to make their trust units more
accessible to U.S. investors. We are monitoring this situation and at this time
have chosen not to pursue a U.S. listing. The Trust is a reporting company with
the Securities and Exchange Commission ("SEC") in the United States and
electronically files its financial statements and other disclosures as required
with the SEC for the benefit of current and potential unitholders residing in
the United States.

UNITHOLDERS' EQUITY

ARC's total capitalization increased 60 per cent to $3 billion during 2003 with
the market value of trust units representing 91 per cent of total
capitalization. During 2003, the market price of the trust units traded in the
$10.89 to $14.87 range with an average daily trading volume of 430,000 units per
day.

On May 16, 2003, the holders of ARC Resources Management Ltd. exchangeable
shares were issued exchangeable shares of ARC Resources Ltd. on a pro-rata basis
as determined by the relative exchange ratio of each series of exchangeable
shares. This transaction had no impact on the total number of trust units
outstanding or issuable for exchangeable shares.

At December 31, 2003, there were 182.8 million trust units issued, issuable for
exchangeable shares and outstanding, a 45 per cent increase from the 126.4
million trust units issued, issuable and outstanding at December 31, 2002. The
significant increase in the number of trust units outstanding is mainly
attributable to the following:

o    the February 25, 2003 equity offering of 12.5 million trust units at $11.50
     per trust unit (before issuance costs). The equity financing raised $144
     million gross proceeds ($136 million net of issuance costs). The proceeds
     were used to reduce existing debt levels on an interim basis and to
     partially fund 2003 capital expenditures;

o    the November 17, 2003 equity offering of 14.5 million trust units at $13.40
     per trust unit (before issuance costs). The equity financing raised $194
     million gross proceeds ($184 million net of issuance costs). The proceeds
     were used to reduce existing debt levels on an interim basis and to
     partially fund 2003 and 2004 capital expenditures; and,

o    the issuance of 27 million trust units at $11.84 per trust unit upon
     conversion of the $320 million convertible debentures issued during the
     Star acquisition.

Unitholders electing to reinvest distributions or make optional cash payments to
acquire trust units from treasury under the Distribution Reinvestment Incentive
Plan (DRIP) may do so at a five per cent discount to the prevailing market price
with no additional fees or commissions. The DRIP plan resulted in an additional
982,563 trust units being issued in 2003 at an average price of $12.68 raising a
total of $12.5 million. In 2002, a total of 242,496 trust units were issued
under the DRIP program at an average price of $12.15 per trust unit.

During 2003, as part of ARC's long-term incentive plan, 2,991,099 trust unit
incentive rights (1,334,072 rights in 2002) were issued to office and field
employees, long-term consultants and independent directors at prices ranging
from $11.59 to $14.74 per trust unit ($11.47 to $12.80 in 2002). The exercise
price of the rights is adjusted downward over time by the amount, if any, that
annual distributions exceed 10 per cent of the net book value of property, plant
and equipment. The rights have a five-year term and vest equally over three
years from the date of grant. Rights to purchase 4,868,888 trust units at an
average adjusted exercise price of $11.29 were outstanding at December 31, 2003.
These rights have an average remaining contractual life of 3.8 years and expire
at various dates to December 2008. Of the rights outstanding at December 31,
2003, a total of 803,255 were exercisable at that time.

CONTRACTUAL OBLIGATIONS:

The following is a summary of the Trust's contractual obligation detailing
payment due for each of the next five years and thereafter:

<PAGE>

MD&A
Page 10
--------------------------------------------------------------------------------

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------
                                                                      Payments Due By Period
----------------------------------------------------------------------------------------------------------------
Contractual Obligations                                                                                 2009 and
($thousands)                               Total           2004        2005-2006       2007-2008      thereafter
----------------------------------------------------------------------------------------------------------------
<S>                                      <C>             <C>           <C>             <C>            <C>
Total debt outstanding (1)               232,402          9,047          174,244          33,602          15,509
Operating leases                          19,594          3,003            5,587           5,502           5,502
----------------------------------------------------------------------------------------------------------------
Purchase commitments (2)                  37,808          3,611            8,591           6,481          19,125
Retention bonuses                          4,000          1,000            2,000           1,000              --
Net contractual obligations              293,804         16,661          190,422          46,585          40,136
----------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Based on the existing terms of the revolving credit facility whereby the
     first payment would be required in 2005. However, it is expected that the
     revolving credit facility will be extended and no repayments will be
     required in the near term. See Note 7 in the financial statements for
     additional information.

(2)  See Note 17 in the financial statements for additional information.

OFF BALANCE SHEET ARRANGEMENTS

The Trust has certain lease agreements which are entered into in the normal
course of operations. All leases are treated as operating leases whereby the
lease payments are included in operating expenses or G&A expenses depending on
the nature of the lease. No asset or liability value has been assigned to these
leases in the balance sheet as of December 31, 2003.

The Trust is required to disclose the nature, terms and estimated fair value of
guarantees in the notes to the financial statements in accordance with
Accounting Guideline 14 - Disclosure of Guarantees ("AcG-14") which is effective
for fiscal years beginning on or after January 1, 2003. The Trust implemented
this new standard in 2003, however there was no impact on the 2003 financial
statements nor disclosure in the Notes to the Financial Statements as a result
of implementation.

CASH DISTRIBUTIONS

ARC declared cash distributions of $279.3 million ($1.80 per unit), representing
71 per cent of 2003 cash flow, bringing total cumulative distributions since
inception to $968.3 million ($12.44 per Trust unit). If cash had been paid out
to the owners of exchangeable shares, the payout ratio would have been 72 per
cent. The remaining 29 per cent of cash flow ($116.9 million) was used to fund
68 per cent of ARC's 2003 capital expenditures ($106.6 million), make
contributions to the reclamation fund ($6.2 million), and make interest payments
on the convertible debentures ($4.1 million). In 2002, declared cash
distributions were $183.6 million ($1.56 per unit), representing 82 per cent of
cash flow. The actual amount withheld is dependent on the commodity price
environment and is at the discretion of the Board of Directors. This holdback
policy differs among the conventional oil and gas trusts. ARC believes it is
essential to focus on production replacement activities partially funded by cash
flow in order to enhance long-term unitholder returns.

Monthly cash distributions for the first quarter of 2004 have been set at $0.15
per trust unit subject to review monthly based on commodity price fluctuations.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices at
that time. The Trust expects to fund the 2004 cash distributions from cash flow.

HISTORICAL DISTRIBUTIONS BY CALENDAR YEAR

CALENDAR YEAR             DISTRIBUTIONS         TAXABLE        RETURN OF CAPITAL
--------------------------------------------------------------------------------
2003 (1)                           1.78            1.51                     0.27
2002                               1.58            1.07                     0.51
2001                               2.41            1.64                     0.77
2000                               1.86            0.84                     1.02
1999                               1.25            0.26                     0.99
1998                               1.20            0.12                     1.08
1997                               1.40            0.31                     1.09
1996                               0.81               -                     0.81
--------------------------------------------------------------------------------
CUMULATIVE                       $12.29           $5.75                    $6.54
================================================================================
(1)  Based on taxable portion of 85 per cent for 2003 distributions

TAXATION OF CASH DISTRIBUTIONS

Cash distributions comprise of a return of capital portion (tax deferred) and a
return on capital portion (taxable). For cash distributions received by a
Canadian resident, outside of a registered pension or retirement plan in the
2003 taxation year, the split between the two is 85 per cent taxable with the
remaining 15 per cent being tax deferred. For a more detailed breakdown, please
visit our website at www.arcresources.com.

<PAGE>

MD&A
Page 11
--------------------------------------------------------------------------------


For 2004, ARC estimates that 85 per cent of cash distributions may be taxable;
15 per cent may be return of capital and used to reduce a unitholder's cost base
on trust units held. Actual taxable amounts will be dependent on commodity
prices experienced throughout the year.

The exchangeable shares of ARC Resources Ltd. ("ARL"), a corporate subsidiary of
the Trust, may provide a more tax-effective basis for investment in the Trust.
The ARL exchangeable shares are traded on the TSX under the symbol "ARX" and are
convertible into trust units, at the option of the shareholder, based on the
then current exchange ratio. Exchangeable shareholders are not eligible to
receive monthly cash distributions, however the exchange ratio increases on a
monthly basis by an amount equal to the current month's trust unit distribution
multiplied by the then current exchange ratio and divided by the 10 day weighted
average trading price of the trust units at the end of each month. The gain
realized as a result of the monthly increase in the exchange ratio is taxed, in
most circumstances, as a capital gain rather than income and is therefore
subject to a lower effective tax rate. Tax on the exchangeable shares is
deferred until the exchangeable share is sold or converted into a trust unit.

<TABLE>
<CAPTION>
2003 DISTRIBUTIONS BY MONTH

                                              TAX DEFERRED AMOUNT
PAYMENT DATE                TAXABLE AMOUNT    (RETURN OF CAPITAL)    TOTAL DISTRIBUTION
---------------------------------------------------------------------------------------
<S>                         <C>                <C>                   <C>
January 15, 2003                $0.1105             $0.0195                  $0.13
February 15, 2003                0.1275              0.0225                   0.15
March 15, 2003                   0.1275              0.0225                   0.15
April 15, 2003                   0.1275              0.0225                   0.15
May 15, 2003                     0.1275              0.0225                   0.15
June 15, 2003                    0.1275              0.0225                   0.15
July 15, 2003                    0.1275              0.0225                   0.15
August 15, 2003                  0.1275              0.0225                   0.15
September 15, 2003               0.1275              0.0225                   0.15
October 15, 2003                 0.1275              0.0225                   0.15
November 15, 2003                0.1275              0.0225                   0.15
December 15, 2003                0.1275              0.0225                   0.15
---------------------------------------------------------------------------------------
Total                           $1.5130             $0.2670                  $1.78  (1)
=======================================================================================
</TABLE>

(1) Total is based upon cash distributions paid during 2003.

FINANCIAL REPORTING AND REGULATORY UPDATE

There have been several changes in the financial reporting and securities
regulatory environment in 2003 that have impacted the Trust and all public
companies. Canadian securities regulators and the Canadian Institute of
Chartered Accountants ("CICA") are undertaking these measures to increase
investor confidence through increased transparency, consistency and
comparability of financial statements and financial information. As well, the
goal of these changes is to align Canadian standards more closely with those in
the United States.

The following new and amended standards were implemented by the Trust in 2003
with the following impact on the 2003 financial statements:

     ASSET RETIREMENT OBLIGATIONS - The CICA issued Section 3110 which
     harmonizes Canadian GAAP with SFAS No.143 "Accounting for Asset Retirement
     Obligations". The new standard requires that companies recognize the
     liability associated with future site reclamation costs in the financial
     statements at the time when the liability is incurred. The new Canadian
     standard is effective for fiscal years beginning on or after January 1,
     2004, however, earlier adoption is recommended. The Trust implemented this
     standard in 2003 in accordance with the early adoption provisions of the
     standard. As a result of implementation, the liability for future
     abandonment costs (the "Asset Retirement Obligation" or "ARO") increased to
     $66.7 million, the PP&E balance increased by $41.1 million and the future
     income tax liability increased by $9 million as at December 31, 2003. Net
     income after applicable income taxes for 2003 increased by $6.4 million
     compared to net income which would have been reported under the old
     standard. The transitional provisions of this section require that the
     standard be applied retroactively with restatement of comparative periods.
     As a result of the retroactive application, 2002 comparative numbers have
     been restated to reflect the impact of this standard on the 2002 financial
     statements. Net income after applicable income taxes for 2002 increased by
     $3.2 million, the ARO increased by $8.4 million, the PP&E balance increased
     by $24.4 million, the future tax liability increased by $8.8 million as at
     December 31, 2002 and opening 2002 retained earnings increased by $8.9
     million net of applicable income taxes. Opening 2003 accumulated earnings
     increased by $12.1 million net of applicable income taxes for the
     cumulative impact of retroactive restatement of all prior years.

<PAGE>

MD&A
Page 12
--------------------------------------------------------------------------------


     STOCK BASED COMPENSATION AND OTHER STOCK BASED PAYMENTS - In September
     2003, the CICA issued an amendment to section 3870 "Stock based
     compensation and other stock based payments". The amended section is
     effective for fiscal years beginning on or after January 1, 2004, however,
     earlier adoption is recommended. The amendment requires that companies
     measure all stock based payments using the fair value method of accounting
     and recognize the compensation expense in their financial statements. The
     Trust implemented this amended standard in 2003 in accordance with the
     early adoption provisions of the standard. Per the transitional provisions,
     early adoption requires that compensation expense be calculated and
     recorded in the income statement for rights issued on or after January 1,
     2003. As a result of implementation of this amended standard, net income of
     the Trust decreased and contributed surplus increased by $3.5 million due
     to the estimated compensation expense on employee rights issued on or after
     January 1, 2003.

     FULL COST ACCOUNTING GUIDELINE - In September 2003, the CICA issued
     Accounting Guideline 16 "Oil and Gas Accounting - Full Cost" to replace
     CICA Accounting Guideline 5. The new guideline proposes amendments to the
     ceiling test calculation applied by the Trust. The new guideline is
     effective for fiscal years beginning on or after January 1, 2004. The Trust
     implemented this new guideline in 2003 in accordance with the transitional
     provisions that encouraged early adoption. Implementation of this new
     guideline did not impact the Trust's financial results for 2003.

     DISCLOSURE OF GUARANTEES - In February 2003, the CICA issued Accounting
     Guideline 14 "Disclosure of Guarantees" which requires that all guarantees
     be disclosed in the notes to the financial statements along with a
     description of the nature and term of the guarantee and an estimate of the
     fair value of the guarantee. The new guideline is effective for fiscal
     years beginning on or after January 1, 2003. Implementation of this new
     guideline did not impact the Trust's financial results for 2003.

The following new and amended standards are expected to impact the Trust in 2004
as follows:

     HEDGING RELATIONSHIPS - In December 2001, the CICA issued Accounting
     Guideline 13 "Hedging Relationships" that deals with the identification,
     designation, documentation and measurement of effectiveness of hedging
     relationships for the purposes of applying hedge accounting. Accounting
     Guideline 13 is intended to harmonize Canadian GAAP with SFAS No.133
     "Accounting for Derivatives Instruments and Hedging Activities". The
     guideline is effective for fiscal years beginning on or after July 1, 2003.
     The Trust has formally documented all transactions that were determined to
     meet the criteria of effective hedges as at December 31, 2003. The Trust
     has assessed the implications of this new guideline that will be
     implemented in 2004.

     CONTINUOUS DISCLOSURE OBLIGATIONS - Effective March 31, 2004, the Trust and
     all reporting issuers in Canada will be subject to new disclosure
     requirements as per National Instrument 51-102 "Continuous Disclosure
     Obligations". This new instrument is effective for fiscal years beginning
     on or after January 1, 2004. The instrument proposes shorter reporting
     periods for filing of annual and interim financial statements, MD&A and the
     Annual Information Form ("AIF"). The instrument also proposes enhanced
     disclosure in the annual and interim financial statements, MD&A and AIF.
     Under this new instrument, it will no longer be mandatory for the Trust to
     mail annual and interim financial statements and MD&A to unitholders, but
     rather these documents will be provided on an "as requested" basis. The
     Trust continues to assess the implications of this new instrument which
     will be implemented in 2004.

     EXCHANGEABLE SHARE ACCOUNTING - On November 10, 2003, the CICA issued a
     draft EIC (D37) on "Income Trusts - Exchangeable Units". The EIC proposes
     that the retained interest of the exchangeable shareholders should be
     presented on the balance sheet as a non-controlling interest separate and
     distinct from unitholder's equity. This draft EIC is currently under review
     and was not enacted in final form as of the time of publication of the
     Trust's consolidated financial statements.

     VARIABLE INTEREST ENTITIES - In June 2003, the CICA issued Accounting
     Guideline 15 "Consolidation of Variable Interest Entities" which deals with
     the consolidation of entities that are subject to control on a basis other
     than ownership of voting interests. This guideline is effective for annual
     and interim periods beginning on or after November 1, 2004. The Trust has
     assessed that this new guideline is not applicable based on the current
     structure of the Trust and therefore will have no impact on the financial
     statements of the Trust. However, this new guideline will be assessed in
     future periods to determine the applicability and resulting financial
     statement implications at that time.

IMPACT ON NET INCOME OF CHANGE IN ACCOUNTING POLICIES

The implementation of new accounting policies in 2003 relating to stock-based
compensation and asset retirement obligations has resulted in restatements of
previously reported annual and quarterly net income. The restatements were
required per the transitional provisions of the respective accounting standards.

<PAGE>

MD&A
Page 13
--------------------------------------------------------------------------------


The following table illustrates the impact of the new accounting policies on
annual net income for years which have been presented for comparative purposes:

<TABLE>
<CAPTION>
($thousands)                                                        2003      2002         2001         2000        1999
------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>        <C>         <C>          <C>          <C>
NET INCOME BEFORE CHANGE IN ACCOUNTING POLICIES (1)              287,307    67,892      138,202      110,872      29,835
Increase (decrease) in net income:
     Stock-based compensation (2)                                 (3,471)       --           --           --          --
     Asset retirement obligation (3)                               6,575     4,855        4,383        3,203       3,154
     Future income tax recovery (expense) (4)                       (210)   (1,700)      (7,113)          --          --
------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) AFTER CHANGE IN ACCOUNTING POLICIES            290,201    71,047      135,472      114,075      32,989
========================================================================================================================
</TABLE>

The following table illustrates the impact of the new accounting policies on
quarterly net income for periods which have been presented for comparative
purposes:

<TABLE>
<CAPTION>
                                                                       2003                                  2002
--------------------------------------------------------------------------------------------------------------------------------
($thousands)                                           Q4         Q3          Q2        Q1        Q4        Q3       Q2       Q1
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>        <C>        <C>        <C>       <C>       <C>      <C>      <C>
NET INCOME (LOSS) BEFORE CHANGE IN ACCOUNTING      55,107     41,217     125,994    64,988    27,596    (3,505)  28,831   14,970
     POLICIES (1)
--------------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in net income:
     Stock-based compensation (2)                  (2,260)    (1,063)       (147)       --        --        --       --      --
     Asset retirement obligation  (3)               1,774      1,812       1,739     1,250     1,114     1,198    1,192   1,351
     Future income tax recovery (expense) (4)       (156)       (431)        573      (196)     (336)     (432)    (380)   (552)
--------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) AFTER CHANGE IN ACCOUNTING       54,465     41,535     128,159    66,042     28,374   (2,739)  29,643  15,769
     POLICIES
================================================================================================================================
</TABLE>

(1)  This represents net income as reported before retroactive restatement for
     changes in accounting policies.

(2)  The new accounting policy for stock-based compensation was implemented in
     the fourth quarter of 2003. The first three quarters of 2003 have been
     restated as a result of this new policy which required restatement of prior
     periods presented for comparative purposes.

(3)  The new accounting policy for asset retirement obligations was implemented
     in the fourth quarter of 2003. This new standard required retroactive
     application with restatement of all periods presented for comparative
     purposes. All periods 1996 through 2003 have been restated on an annual and
     quarterly basis as a result of this new policy.

(4)  Future income tax expense/recovery has been restated to reflect the impact
     of the retroactive restatement of prior periods for the accounting for
     asset retirement obligations. No future income tax expense/recovery
     adjustment was recorded for 1999 and 2000 due to the fact that the Trust
     had future tax assets in excess of future tax liabilities in those years.

ASSESSMENT OF BUSINESS RISKS

The ARC management team is focused on long-term strategic planning and has
identified the following items as risks and in certain cases, opportunities
associated with the Trust's business.

     RESERVE ESTIMATES

     The reserve and recovery information contained in ARC's independent reserve
     evaluation is only an estimate. The actual production and ultimate reserves
     from the properties may be greater or less than the estimates prepared by
     the independent reserve evaluator. A significant portion of the principal
     properties acquired in the Star acquisition have relatively short
     production histories which may make estimates on those properties more
     subject to revisions. The reserve report was prepared using certain
     commodity price assumptions that are described in the notes to the reserve
     tables. If lower prices for crude oil, natural gas liquids and natural gas
     are realized by the Trust and substituted for the price assumptions
     utilized in those reserve reports, the present value of estimated future
     net cash flows for the Trust's reserves would be reduced and the reduction
     could be significant, particularly based on the constant price case
     assumptions.

     VOLATILITY OF OIL AND NATURAL GAS PRICES

     The Trust's operational results and financial condition, and therefore the
     amount of distributions paid to the unitholders will be dependent on the
     prices received for oil and natural gas production. Oil and natural gas
     prices have fluctuated widely during recent years and are determined by
     economic and in the case of oil prices, political

<PAGE>

MD&A
Page 14
--------------------------------------------------------------------------------


     factors. Supply and demand factors, including weather and general economic
     conditions as well as conditions in other oil and natural gas regions
     impact prices. Any movement in oil and natural gas prices could have an
     effect on the Trust's financial condition and therefore on the
     distributions to the holders of trust units. ARC may manage the risk
     associated with changes in commodity prices by entering into oil or natural
     gas price hedges. If ARC hedges its commodity price exposure, the Trust
     will forego the benefits it would otherwise experience if commodity prices
     were to increase. In addition, commodity hedging activities could expose
     ARC to losses. To the extent that ARC engages in risk management activities
     related to commodity prices, it will be subject to credit risks associated
     with counterparties with which it contracts.

     VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES

     Variations in interest rates could result in a significant increase in the
     amount the Trust pays to service debt, resulting in a decrease in
     distributions to unitholders. World oil prices are quoted in U.S. dollars
     and the price received by Canadian producers is therefore affected by the
     Canadian/U.S. dollar exchange rate that may fluctuate over time. A material
     increase in the value of the Canadian dollar may negatively impact the
     Trust's net production revenue. In addition, the exchange rate for the
     Canadian dollar versus the U.S. dollar has increased significantly over the
     last 12 months, resulting in the receipt by the Trust of fewer Canadian
     dollars for its production which may affect future distributions. ARC has
     initiated certain hedges to attempt to mitigate these risks. To the extent
     that ARC engages in risk management activities related to foreign exchange
     rates, it will be subject to credit risk associated with counterparties
     with which it contracts. The increase in the exchange rate for the Canadian
     dollar and future Canadian/United States exchange rates will impact future
     distributions and the future value of the Trust's reserves as determined by
     independent evaluators.

     CHANGES IN LEGISLATION

     Income tax laws, or other laws or government incentive programs relating to
     the oil and gas industry, such as the treatment of mutual fund trusts and
     resource taxation, may in the future be changed or interpreted in a manner
     that adversely affects the Trust and its unitholders. Tax authorities
     having jurisdiction over the Trust or the unitholders may disagree with how
     the Trust calculates its income for tax purposes or could change
     administrative practices to the detriment of the Trust or the detriment of
     its unitholders. ARC intends that the Trust will continue to qualify as a
     mutual fund trust for purposes of the Tax Act. The Trust may not, however,
     always be able to satisfy any future requirements for the maintenance of
     mutual fund trust status. Should the status of the Trust as a mutual fund
     trust be lost or successfully challenged by a relevant tax authority,
     certain adverse consequences may arise for the Trust and its unitholders.

     OPERATIONAL MATTERS

     The operation of oil and gas wells involves a number of operating and
     natural hazards that may result in blowouts, environmental damage and other
     unexpected or dangerous conditions resulting in damage to operating
     subsidiaries of the Trust and possible liability to third parties. ARC will
     maintain liability insurance, where available, in amounts consistent with
     industry standards. Business interruption insurance may also be purchased
     for selected facilities, to the extent that such insurance is available.
     ARC may become liable for damages arising from such events against which it
     cannot insure or against which it may elect not to insure because of high
     premium costs or other reasons. Costs incurred to repair such damage or pay
     such liabilities will reduce distributable cash.

     Continuing production from a property, and to some extent the marketing of
     production therefrom, are largely dependent upon the ability of the
     operator of the property. Operating costs on most properties have increased
     steadily over recent years. To the extent the operator fails to perform
     these functions properly, revenue may be reduced. Payments from production
     generally flow through the operator and there is a risk of delay and
     additional expense in receiving such revenues if the operator becomes
     insolvent. Although satisfactory title reviews are generally conducted in
     accordance with industry standards, such reviews do not guarantee or
     certify that a defect in the chain of title may not arise to defeat the
     claim of the Trust to certain properties. A reduction of the distributions
     could result in such circumstances.

     EXPANSION OF OPERATIONS

     The operations and expertise of management of the Trust are currently
     focused on conventional oil and gas production and development in the
     western Canadian sedimentary basin. In the future, the Trust may acquire
     oil and gas properties outside this geographic area. In addition, the Trust
     Indenture does not limit the activities of the Trust to oil and gas
     production and development, and the Trust could acquire other energy
     related assets, such as oil and natural gas processing plants or pipelines,
     or an interest in an oil sands project. Expansion of our activities into
     new areas may present new additional risks or alternatively, significantly
     increase the exposure to one or more of the present risk factors, which may
     result in future operational and financial conditions of the Trust being
     adversely affected.

<PAGE>

MD&A
Page 15
--------------------------------------------------------------------------------


     ACQUISITIONS

     The price paid for reserve acquisitions is based on engineering and
     economic estimates of the reserves made by independent engineers modified
     to reflect the technical views of management. These assessments include a
     number of material assumptions regarding such factors as recoverability and
     marketability of oil, natural gas, natural gas liquids and sulphur, future
     prices of oil, natural gas, natural gas liquids and sulphur and operating
     costs, future capital expenditures and royalties and other government
     levies which will be imposed over the producing life of the reserves. Many
     of these factors are subject to change and are beyond the control of the
     operators of the working interests, management and the Trust. In
     particular, changes in the prices of and markets for petroleum, natural
     gas, natural gas liquids and sulphur from those anticipated at the time of
     making such assessments will affect the amount of future distributions and
     as such the value of the trust units. In addition, all such estimates
     involve a measure of geological and engineering uncertainty which could
     result in lower production and reserves than attributed to the working
     interests. Actual reserves could vary materially from these estimates.
     Consequently, the reserves acquired may be less than expected, which could
     adversely impact cash flows and distributions to unitholders.

     ENVIRONMENTAL CONCERNS

     The oil and natural gas industry is subject to environmental regulation
     pursuant to local, provincial and federal legislation. A breach of such
     legislation may result in the imposition of fines or issuance of clean up
     orders in respect of ARC or its working interests. Such legislation may be
     changed to impose higher standards and potentially more costly obligations
     on ARC. Although ARC has established a reclamation fund for the purpose of
     funding its currently estimated future environmental and reclamation
     obligations based on its current knowledge, there can be no assurance that
     the Trust will be able to satisfy its actual future environmental and
     reclamation obligations. Additionally, the potential impact on the Trust's
     operations and business of the December 1997 Kyoto Protocol, which has now
     been ratified by Canada, with respect to instituting reductions of
     greenhouse gases, is difficult to quantify at this time as specific
     measures for meeting Canada's commitments have not been developed.

     DEBT SERVICE

     Amounts paid in respect of interest and principal on debt will reduce
     distributions. Variations in interest rates and scheduled principal
     repayments could result in significant changes in the amount required to be
     applied to debt service before payment of distributions. Certain covenants
     of the agreements with ARC's lenders may also limit distributions. Although
     ARC believes the credit facilities will be sufficient for the Trust's
     immediate requirements, there can be no assurance that the amount will be
     adequate for the future financial obligations of the Trust or that
     additional funds will be able to be obtained.

     The lenders will be provided with security over substantially all of the
     assets of ARC. If ARC becomes unable to pay its debt service charges or
     otherwise commits an event of default such as bankruptcy, the lender may
     foreclose on or sell the working interests.

     DEPLETION OF RESERVES

     The Trust has certain unique attributes which differentiate it from other
     oil and gas industry participants. Distributions, absent commodity price
     increases or cost effective acquisition and development activities, will
     decline over time in a manner consistent with declining production from
     typical oil, natural gas and natural gas liquids reserves. ARC will not be
     reinvesting cash flow in the same manner as other industry participants as
     ARC conducts only minimal exploratory activities; nor to the same extent as
     other industry participants as one of the main objectives of the Trust is
     to maximize long-term distributions. Accordingly, absent capital
     injections, ARC's initial production levels and reserves will decline.

     ARC's future oil and natural gas reserves and production, and therefore its
     cash flows, will be highly dependent on ARC's success in exploiting its
     reserve base and acquiring additional reserves. Without reserve additions
     through acquisition or development activities, the Trust's reserves and
     production will decline over time as reserves are exploited.

     To the extent that external sources of capital, including the issuance of
     additional trust units become limited or unavailable, ARC's ability to make
     the necessary capital investments to maintain or expand its oil and natural
     gas reserves will be impaired. To the extent that ARC is required to use
     cash flow to finance capital expenditures or property acquisitions, the
     level of distributions will be reduced.

     There can be no assurance that ARC will be successful in developing or
     acquiring additional reserves on terms that meet the Trust's investment
     objectives.

<PAGE>

MD&A
Page 16
--------------------------------------------------------------------------------


     NET ASSET VALUE

     The net asset value of the assets of the Trust will vary from time to time
     dependent upon a number of factors beyond the control of management,
     including oil and gas prices. The trading prices of the trust units from
     time to time are also determined by a number of factors that are beyond the
     control of management and such trading prices may be greater than the net
     asset value of the Trust's assets.

     ADDITIONAL FINANCING

     In the normal course of making capital investments to maintain and expand
     the oil and gas reserves of the Trust, additional trust units are issued
     from treasury which may result in a decline in production per trust unit
     and reserves per trust unit. Additionally, from time to time the Trust
     issues trust units from treasury in order to reduce debt and maintain a
     more optimal capital structure. Conversely, to the extent that external
     sources of capital, including the issuance of additional trust units,
     become limited or unavailable, the Trust's ability to make the necessary
     capital investments to maintain or expand its oil and gas reserves will be
     impaired. To the extent that ARC is required to use cash flow to finance
     capital expenditures or property acquisitions, to pay debt service charges
     or to reduce debt, the level of distributable income will be reduced.

     COMPETITION

     There is strong competition relating to all aspects of the oil and gas
     industry. There are numerous trusts in the oil and gas industry that are
     competing for the acquisitions of properties with longer life reserves and
     properties with exploitation and development opportunities. As a result of
     such increasing competition, it will be more difficult to acquire reserves
     on beneficial terms. ARC competes for reserve acquisitions and skilled
     industry personnel with a substantial number of other oil and gas
     companies, many of which have significantly greater financial and other
     resources than the Trust.

     RETURN OF CAPITAL

     Trust units will have no value when reserves from the properties can no
     longer be economically produced and, as a result, cash distributions do not
     represent a "yield" in the traditional sense as they represent both a
     return of capital and a return on investment.

     MAINTENANCE OF DISTRIBUTIONS

     ARC has adopted a general policy of investing approximately 20 per cent of
     annual cash flow from the properties in capital expenditures for the
     development and exploitation of the properties in order to mitigate the
     natural declines in production from the properties. There can be no
     assurance that capital expenditures in the amounts invested and planned to
     be invested can be maintained nor that the volumes of production can be
     maintained at current levels; nor as a consequence, that the amount of
     distributions by the Trust to unitholders can be maintained at current
     levels.

     NON-RESIDENT OWNERSHIP OF TRUST UNITS

     In order for the Trust to maintain its status as a mutual fund trust under
     the Tax Act, the Trust intends to comply with the requirements of the Tax
     Act for "mutual fund trusts" at all relevant times. In this regard, the
     Trust shall among other things, monitor the ownership of the trust units to
     carry out such intentions. The Trust Indenture provides that if at any time
     the Trust becomes aware that the beneficial owners of 50 per cent or more
     of the trust units then outstanding are or may be non-residents or that
     such a situation is imminent, the Trust shall take such action as may be
     necessary to carry out the foregoing intention.

     ACCOUNTING WRITE-DOWNS AS A RESULT OF GAAP

     Canadian Generally Accepted Accounting Principles ("GAAP") require that
     management apply certain accounting policies and make certain estimates and
     assumptions that affect reported amounts in the consolidated financial
     statements of the Trust. The accounting policies may result in non-cash
     charges to net income and write-downs of net assets in the financial
     statements. Such non-cash charges and write-downs may be viewed unfavorably
     by the market and result in an inability to borrow funds and/or may result
     in a decline in the trust unit price. The carrying value of property, plant
     and equipment, the carrying value of goodwill and the value of hedging
     instruments are some of the items which are subject to valuation and
     potential non-cash write-downs.

     NATURE OF TRUST UNITS

     The Trust units do not represent a traditional investment in the oil and
     natural gas sector and should not be viewed by investors as shares in a
     corporation. The trust units represent a fractional interest in the Trust.
     As holders of trust units, unitholders will not have the statutory rights
     normally associated with ownership of shares of a corporation. The Trust's
     sole assets will be the royalty interests in the properties. The price per
     trust unit is a function of anticipated distributable income, the
     properties acquired by ARC and ARC's ability to effect long-term growth in
     the value of the Trust. The market price of the trust units will be
     sensitive to a variety of market

<PAGE>
MD&A
Page 17
--------------------------------------------------------------------------------


     conditions including, but not limited to, interest rates and the ability of
     the Trust to acquire suitable oil and natural gas properties. Changes in
     market conditions may adversely affect the trading price of the trust
     units.

MANAGEMENT AND FINANCIAL REPORTING SYSTEMS

The Trust has continuously evolved and documented its management and internal
reporting systems to provide assurance that accurate, timely internal and
external information is gathered and disseminated.

The Trust's financial and operating results incorporate certain estimates
including:

     a)  estimated revenues, royalties and operating costs on production as at a
         specific reporting date but for which actual revenues and costs have
         not yet been received;

     b)  estimated capital expenditures on projects that are in progress; and

     c)  estimated depletion, depreciation and accretion and reported FD&A costs
         that are based on estimates of oil and gas reserves that the Trust
         expects to recover in the future.

The Trust has hired individuals and consultants who have the skill set to make
such estimates and ensures individuals or departments with the most knowledge of
the activity are responsible for the estimate. Further, past estimates are
reviewed and compared to actual results in order to make more informed decisions
on future estimates.

The ARC management team's mandate includes ongoing development of procedures,
standards and systems to allow ARC staff to make the best decisions possible and
ensuring those decisions are in compliance with the Trust's environmental,
health and safety policies.


2004 CASH FLOW SENSITIVITY

Below is a table that shows sensitivities to pre-hedging cash flow with
operational changes and changes to the business environment:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                             IMPACT ON ANNUAL        IMPACT ON ANNUAL
                                                                 CASH FLOW           DISTRIBUTIONS (2)
                               ASSUMPTION     CHANGE          $/UNIT        %             $/UNIT
--------------------------------------------------------------------------------------------------------
<S>                            <C>            <C>           <C>          <C>         <C>
BUSINESS ENVIRONMENT
Price per barrel of oil
(US$WTI) (1)                      $30.00       $1.00          $0.05       3.2%            $0.04
Price per mcf of natural
   gas (CDN$AECO) (1)              $5.25       $0.10          $0.03       1.6%            $0.02
CDN/USD exchange rate              $0.75       $0.01          $0.03       2.0%            $0.03
Interest rate on debt               4.3%        1.0%          $0.02       1.0%            $0.01
--------------------------------------------------------------------------------------------------------
OPERATIONAL
Liquids production volume         27,000        1.0%          $0.01       0.5%            $0.01
Gas production volumes           168,000        1.0%          $0.01       0.6%            $0.01
Operating expenses per boe         $7.20        1.0%          $0.01       0.4%            $0.01
G&A expenses per boe               $1.10       10.0%          $0.01       0.7%            $0.01
========================================================================================================
</TABLE>

(1) Analysis does not include the effect of hedging.

(2) Analysis assumes a 20 per cent holdback on distributions.

The Trust is continually evaluating potential acquisitions with all acquisitions
in excess of $10 million subject to Board approval. The Trust's business plan
could result in multiple acquisitions in one fiscal year. As the nature of
acquisitions in the energy business usually involves a competitive bid process,
we cannot predict whether the Trust will execute any acquisitions in the future.
The Trust's scope of acquisitions being evaluated encompasses energy assets,
including conventional oil and gas assets, oil sands interests, coal bed
methane, electricity or power generating assets and pipeline, gathering and
transportation assets.

The management of the Trust has financed the purchase of conventional oil and
gas assets in the past primarily by the issue of trust units and has ensured the
Trust's financial ratios are comparable to other similar organizations. If the
Trust acquired energy assets other than conventional oil and gas assets it would
review alternatives for financing such acquisitions, which may result in a
higher use of debt, but with the view of having the Trust's debt to total
capitalization being comparable to similar sized organizations with a similar
mix of assets.


<PAGE>

MD&A
Page 18
--------------------------------------------------------------------------------


OUTLOOK

It is the Trust's objective to provide the highest possible long-term returns to
unitholders by focusing on the key strategic objectives of the business plan.
This focus has resulted in ARC Energy Trust achieving excellent results since
inception in July 1996, by providing unitholders with cash distributions of
$12.44 per trust unit and capital appreciation of $4.74 per trust unit for a
total return of $17.18 per trust unit for untholders who invested in the Trust
at inception.

The key future objectives of the business plan, which is reviewed with the Board
of Directors, includes:

     o   annual reserve replacement;

     o   ensuring acquisitions are strategic and enhance unitholder returns;

     o   controlling costs - FD&A costs, operating costs and G&A expenses;

     o   actively hedging a portion of the Trust's production to stabilize
         distributions;

     o   conservative utilization of debt;

     o   continuously developing the expertise of our staff and seeking to hire
         and retain the best in the industry;

     o   building business relationships so as to be viewed as fair and
         equitable in all business dealings;

     o   promoting the use of proven and effective technologies;

     o   being an industry leader in the environment, health and safety area;
         and

     o   continuing to actively support local initiatives in the communities in
         which we operate and live.

In 2003, the Trust was successful in meeting or exceeding all of the above
objectives and will continue to focus on and closely monitor these core
objectives in 2004 and beyond.

In 2004, ARC will be busy with an active drilling and development program on its
expanded asset base. The $175 million capital expenditure budget is the largest
in its history. The Trust will focus on major properties with significant
upside, with the objective to replace production declines with internal
development opportunities.

The equity offering that closed on November 17, 2003, raised $184 million of net
proceeds for the Trust, reducing the Trust's net debt at year-end to $262
million or approximately 0.7 times 2003 cash flow. This low level of debt
provides the Trust the financial flexibility to fund the 2004 capital
expenditure program of and be poised to take advantage of positive acquisition
opportunities.

ADDITIONAL INFORMATION

Additional information relating to ARC, including the Annual Information Form
which is filed yearly within 140 days after year-end, can be found on SEDAR at
www.sedar.com.


<PAGE>

MD&A
Page 19
--------------------------------------------------------------------------------


<TABLE>
<CAPTION>
HISTORICAL REVIEW
For the years ended December 31
($thousands, except per unit and volume amounts)                 2003        2002        2001        2000        1999
----------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>         <C>         <C>         <C>         <C>
FINANCIAL
Revenue before royalties                                      731,233     444,835     515,596     316,270     155,191
         Per unit (1)                                          $ 4.73      $ 3.72      $ 5.05      $ 4.97      $ 3.34
Cash flow                                                     396,180     223,969     260,270     179,349      80,814
         Per unit (1)                                          $ 2.56      $ 1.87      $ 2.55      $ 2.82      $ 1.74
Net income (5) (6)                                            290,201      71,047     135,472     114,075      32,989
         Per unit (1) (5) (6) (7)                              $ 1.85      $ 0.59      $ 1.33      $ 1.79      $ 0.71
Cash distributions                                            279,328     183,617     234,053     128,958      63,773
         Per unit (2)                                          $ 1.80      $ 1.56      $ 2.31      $ 2.01      $ 1.35
Net debt outstanding                                          262,071     347,795     288,684     108,729     125,239
Weighted average trust units
         and exchangeable shares (3)                          154,695     119,613     101,979      63,681      46,480
Trust units and units issuable for
         exchangeable shares at end of period (3)             182,777     126,444     111,692      72,524      53,607
----------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical                                      5,671       1,966       2,215         466         186
Drilling and completions                                      110,277      70,074      73,147      39,021      20,974
Plant and facilities                                           36,457      14,357      22,970      13,999       2,743
Other capital                                                   3,359       1,881       3,886         554         347
Total capital expenditures                                    155,764      88,278     102,218      54,040      24,250
Property acquisitions (dispositions), net                   (161,609)     119,113      12,911     153,877    (10,964)
Corporate acquisitions                                        721,590          --     509,748          --     242,446
Total capital expenditures and net acquisitions               715,745     207,391     624,877     207,917     255,732
----------------------------------------------------------------------------------------------------------------------
OPERATING
Production
         Crude oil (bbl/d)                                     22,886      20,655      20,408      11,528       8,408
         Natural gas (mmcf/d)                                   164.2       109.8       115.2        77.2        66.5
         Natural gas liquids (bbl/d)                            4,086       3,479       3,511       2,965       2,687
         Total (boe/d) (4)                                     54,335      42,425      43,111      27,355      22,172
Average prices
         Crude oil ($/bbl)                                      34.48       31.63       31.70       36.74       24.85
         Natural gas ($/mcf)                                     6.21        4.41        5.72        4.48        2.54
         Natural gas liquids ($/bbl)                            32.19       24.01       31.03       31.52       17.43
         Oil equivalent ($/boe)                                 36.87       28.73       32.76       31.59       19.15
----------------------------------------------------------------------------------------------------------------------

<CAPTION>
RESERVES *                                          2003
Proved plus probable reserves             Gross Reserves                   Company Interest Reserves
                                       -------------------------------------------------------------------------------
<S>                                              <C>          <C>         <C>         <C>         <C>         <C>
         Crude oil and NGL (mbbl)                128,871      129,663     117,241     114,243      82,419      59,712
         Natural gas (bcf)                         705.6        720.2       408.8       385.5       286.4       241.0
         Total (mboe)                            246,468      249,704     185,371     178,496     130,147      99,879
----------------------------------------------------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit Prices
         High                                                 $ 14.87     $ 13.44     $ 13.54     $ 12.15      $ 9.35
         Low                                                  $ 10.89     $ 11.04     $ 10.25      $ 8.35      $ 6.10
         Close                                                $ 14.74     $ 11.90     $ 12.10     $ 11.30      $ 8.75
Daily average trading volume (thousands)                          430         305         414         151          68
</TABLE>

* Established reserves for 2002 and prior years.

<PAGE>

MD&A
Page 20
--------------------------------------------------------------------------------


(1)  Based on weighted average trust units and exchangeable shares.

(2)  Based on number of trust units outstanding at each cash distribution date.

(3)  Includes trust units issuable for outstanding exchangeable shares based on
     the period-end exchange ratio

(4)  Natural gas converted at 6:1.

(5)  2001 net income and net income per unit have been restated for the
     retroactive change in accounting policy for deferred foreign exchange
     translation.

(6)  Net income and net income per unit has been restated for years 1999 through
     2002 and for the first quarter of 2002 through the third quarter of 2003.
     The restatement was the result of the retroactive application of the change
     in accounting policy relating to Asset Retirement Obligations which was
     implemented in the fourth quarter of 2003.

(7)  Net income in the basic per trust unit calculation has been reduced by
     interest on the convertible debentures.


<PAGE>

MD&A
Page 21
--------------------------------------------------------------------------------


<TABLE>
<CAPTION>
QUARTERLY REVIEW
                                                                  2003                               2002
($thousands, except per unit and volume amounts)    Q4         Q3        Q2          Q1        Q4         Q3        Q2        Q1
--------------------------------------------------------------------------------------------------------------------------------
FINANCIAL
<S>                                            <C>        <C>        <C>        <C>       <C>        <C>       <C>       <C>
Revenue before royalties                       178,927    180,596    195,081    176,629   117,639    113,625   112,707   100,864
         Per unit (1)                             1.02       1.09       1.34       1.34      0.93       0.91      0.98      0.90
Cash flow                                       89,617     87,511    116,546    102,506    61,495     56,603    56,677    49,194
         Per unit (1)                             0.51       0.53       0.80       0.78      0.49       0.45      0.49      0.44
Net income (loss) (5) (6)                       54,465     41,535    128,159     66,042    28,374    (2,739)    29,643    15,769
         Per unit (7)                             0.31       0.25       0.85       0.50      0.22     (0.02)      0.26      0.14
Cash distributions                              78,603     73,890     67,495     59,340    48,060     47,644    44,684    43,229
         Per unit (2)                             0.45       0.45       0.45       0.45      0.39       0.39      0.39      0.39
Net debt outstanding                           262,071    412,686    466,988    226,583   347,795    271,203   209,674   312,821
Weighted average units (thousands) (3)         174,991    166,365    145,546    131,379   126,370    124,794   115,235   111,838
--------------------------------------------------------------------------------------------------------------------------------
Units outstanding and issuable
     at period end (3)                         182,777    167,531    163,184    139,239   126,444    126,270   122,359   111,957

CAPITAL EXPENDITURES
($thousands)
Geological and geophysical                       2,846      1,171        656        998       556        619       519       272
Drilling and completions                        37,738     31,661     23,834     17,037    21,047     12,025    13,538    23,464
Plant and facilities                            15,512     11,917      4,831      4,204     4,265      3,115     2,944     4,033
Other capital                                    1,418        391      1,325        224       861        380       285       355
--------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures                      57,515     45,140     30,646     22,463    26,729     16,139    17,286    28,124
Property acquisitions (dispositions), net       (3,693)   (81,166)   (79,750)     3,000    61,952     46,018     9,344     1,799
Corporate acquisitions                              --        258    721,332         --        --         --        --        --
Total capital expenditures and
    net acquisitions                            53,822   (35,768)    672,228     25,463    88,681     62,157    26,630    29,923

OPERATING
Production
         Crude oil (bbl/d)                      22,851     23,522     24,078     21,065    20,256     20,809    20,366    21,196
         Natural gas (mmcf/d)                    180.8      182.0      175.7      117.3     109.2      109.1     106.9     113.9
         Natural gas liquids (bbl/d)             4,140      4,105      4,397      3,696     3,355      3,408     3,527     3,631
         Total (boe/d 6:1)                      57,120     57,968     57,759     44,313    41,808     42,394    41,713    43,805
Average prices
         Crude oil ($/bbl)                       31.69      32.76      33.71      40.41     30.20      33.68     32.40     30.22
         Natural gas ($/mcf)                      5.65       5.44       6.39       8.04      5.26       4.11      4.67      3.61
         Natural gas liquids ($/bbl)             30.14      30.92      28.83      39.99     27.49      25.23     23.38     20.17
         Oil equivalent ($/boe 6:1)              34.05      33.86      37.12      44.29     30.58      29.13     29.69     25.58
--------------------------------------------------------------------------------------------------------------------------------

TRUST UNIT TRADING
(based on intra-day trading)
Unit Prices
         High                                  $ 14.87    $ 13.88    $ 12.84    $ 12.34    $12.74    $ 12.98   $ 13.44   $ 13.18
         Low                                   $ 13.31    $ 12.51    $ 11.29    $ 10.89    $11.04    $ 11.05   $ 11.85   $ 11.35
         Close                                 $ 14.74    $ 13.55    $ 12.50    $ 11.59    $11.90    $ 12.80   $ 12.77   $ 13.14
Daily average trading volume (thousands)           395        551        503        313       269        256       252       446
================================================================================================================================
</TABLE>

(1)  Based on weighted average trust units and exchangeable shares.

(2)  Based on number of trust units outstanding at each cash distribution date.

(3)  Includes trust units issuable for outstanding exchangeable shares based on
     the period end exchange ratio.

(4)  Natural gas converted at 6:1.

(5)  2001 net income and net income per unit have been restated for the
     retroactive change in accounting policy for deferred foreign exchange
     translation.

(6)  Net income and net income per unit have been restated for years 1999
     through 2002 and for the first quarter of 2003 through the third quarter of
     2003. The restatement was the result of the retroactive application of the
     change in accounting policy relating to Asset Retirement Obligations that
     was implemented in the fourth quarter of 2003.

(7)  Net income in the basic per trust unit calculation has been reduced by
     interest on the convertible debentures.